Method for determination of flow rate in a fluid

ABSTRACT

A method for measuring the flow rate in a fluid flow, particularly a two-phase flow comprising oil, water and gas from an offshore well, in which a temporary transitory shut-off of the fluid flow by means of a valve is performed, and the fluid pressure at a location immediately upstream of the valve is recorded from a moment of time when the valve starts closing to a selected moment of time after the valve is fully closed. Subsequently, the valve is opened to reestablish the fluid flow, and the fluid mass flux G is determined as a function of fluid density, friction factor, pipe diameter, selected moment of time after closure of the valve, friction loss recorded at the selected moment after closure and a pressure surge pressure.

The present invention concerns a method for determining the flow rate ina fluid flow, particularly in a two-phase flow comprising oil/water/gasfrom a production well offshore.

BACKGROUND

Measuring of multi-phase flows in oil wells and pipelines includingother different flow systems is a serious unsolved problem within thepetroleum industry. A complete measurement of a multi-phase flow in e.g.an oil well comprises the three phases gas, oil and water.

In measurements of gas/liquid one has to determine the means flow rateof the composition and the mean density. The total flow rate can then bedetermined.

In general, it is more convenient to determine the composition densitythan its flow velocity by means of the known measuring methods forgas/liquid. According to these methods, the density is usually obtainedby means of a gamma ray meter. Methods which are under development formeasuring multi-phase and gas/liquid employ metering of the waterfraction substantially based upon dielectric properties of thehydrocarbon/water composition.

In a multiphase hydrocarbon/water composition, when the multi-phasetotal density has been obtained by means of a gamma ray meter and thewater fraction, the oil fraction and water fraction can be estimated.The apparatus for metering of water fraction usually has a simple androbust construction, and can therefore be implemented on productionplatforms offshore and possibly in installation below sea level.

However, gamma ray meters are expensive and can not be modified at a lowcost to enable them to be used reliably in the harsh conditions existingon production platforms offshore and installations below sea level forcommercial metering of well head fluids or fluids in pipelines.Moreover, the radioactive gamma ray source requires strict securityregulations.

Capacitance methods are being developed to detect the quantities ofhydrocarbons and water flowing in a pipe. This method is howeversensitive to water; e.g., the method measures the quantity ofwaterflowing, whereby the remaining flow is constituted by hydrocarbons.However, this method cannot differentiate between liquid hydrocarbonsand gaseous hydrocarbons. The capacitance method is also influenced bythe gas/liquid ratio, which calls for a correction of the measuringresults in view of an independent measuring result for a gas/liquidfraction, provided from e.g., a gamma ray meter.

Techniques using microwaves are being developed. Microwaves are absorbedby water, and as with the capacitance meter the remainder of the mediumis assumed to be hydrocarbons. The microwave technique (and thecapacitance method) are also influenced by the gas/liquid ratio.Therefore, calibration is required. On the other hand it is possible touse the microwave technique in cross-correlation, but because of thelarge volume of the measuring technique, only special features of themulti-phase flow in a large scale are detectable.

While the capacitance method and the microwave technique do in generalhave the same field of use they also have the same limitations.

In connection with research activity and with commercial activitydevelopment is proceeding on metering equipment consisting of twometers: a gamma ray meter and a capacitance or a microwave meter, inwhich one provides the gas/liquid ratio, and the other the waterquantity. However, methods of this type are limited to narrow gas/liquidfractions, particular flow regimes or other particular conditions. Thesemethods can therefore not provide reliable measurements of the flowvelocity in multi-phase systems over a wide range of conditions.

An alternative metering method for use with multi-phase systems isdescribed in NO Patent No. 174643. This patent describes a method formetering of flow velocity and quantity or mass ratio between differentphases in pipes and wells in which the flowing medium comprises severalphases, particularly two-phase systems of the natural gas and oil type.A pressure pulse generator arranged in or adjacent to the pipe or thewell produces a low frequent pressure pulse (<100 Hz) which propagatesboth upstream and downstream through the flowing medium. The pressurepulse is recorded by two pressure transductors located respectivelyupstream and downstream of the pressure pulse generator and located at aknown distance from the pressure pulse generator.

Using a time difference basis between the pressure pulse propagationtime through the medium from the pressure pulse generator to therespective pressure transductors, the flow velocity of the medium can becalculated. The mass ratio between the different phases can bedetermined by subtracting the absolute flow velocity of the medium fromthe measured propagation velocity measured, and then comparing the realpropagation velocity with theoretical or empirical data. The lowfrequent pressure pulse will absorb to a far less extent than pulseshaving a higher frequency, thus enabeling a substantially exact massmeasurement of a two-phase flow.

OBJECT

The main object of the present invention is to provide a method formeasuring the flow rate in a fluid flow, particularly multi-phase flowsin oil wells and connected pipelines, by using a minimum of meteringequipment.

THE INVENTION

In accordance with the invention one can obtain values representing massflow of gas and liquid in a fluid flow by performing a temporary butcomplete shut-down of the fluid flow by means of a relatively fastclosing valve, and recording changes in fluid pressure by means of atleast one pressure sensor located immediately upstream of the shut-offvalve. As described in further detail below, the recorded pressuresignals are transmitted to a processing unit which performs the requiredcalculations.

In this way it is possible to provide values for flow rate at a momentin time, immediately before shutting off the fluid flow, by means ofonly one pressure sensor and a connected signal processing unit, inother words by means of a minimum of extra equipment. This supposes thatthe fluid density and specific acoustic sound velocity are known. If thespecific acoustic speed and density are not known a simultaneousmetering of these parameters can be performed with two extra pressuresensors, one of which (reference sensor) is located immediatelydownstream of the shut-off valve and the second located at a knowndistance downstream of the reference sensor.

In measurements of multi-phase flows, the present method is best suitedfor metering of relatively stable and homogenous flows, such as thosefound in oil wells in the North Sea, and in systems in which shorttemporary shut-downs of the fluid flow is permitted.

For ease of description and interpretation of the invention there is setforth an example with a subsea well. The person skilled in the art willhowever, based on his/her knowledge and the present description easilyrealize that the metering method can be used with other multi-phaseflows without any substantial modifications.

Definition

The term "quick closing valve" means a shut-off valve which closeswithin a short period of time, e.g., within less than 10 seconds. Inmetering of a multi-phase flow from an oil production well, thehydraulically actuated wing valve located at the well head can be used.Common wing valves can close within less than 5 seconds. The term quidclosing is in this context not meant to encompass the specialized quickclosing valves which are in use with multi-phase laboratories whichcloses within one second or less. This permits the use of existingequipment.

The term "pressure sensor" means in this connection a pressuretransducer which allows a relatively large number of pressuremeasurements of the fluid pressure per unit time during a period of timein the range of some tens of seconds. A pressure sensor performing 100measurements per second will be satisfactory in most situations. Themost important is that the sensor provides a sufficiently large numberof measurements per unit of time to reproduce or translate the pressurecourse with sufficient degree of accuracy.

DESCRIPTION OF THE FIGURES

FIG. 1 is a schematic illustration of an arrangement for metering ofmass flux in a multi-phase flow from an oil well for which the specificacoustic velocity of the medium including its density are known.

FIG. 2 is a diagram illustrating the general pressure course duringshut-off of a valve.

FIG. 3 shows an alternative embodiment of the arrangement of FIG. 1 toadditionally determine the specific acoustic velocity of the medium.

FIG. 4 shows schematically an alternative use of the present method inconnection with NO Patent No. 174643.

FIG. 5 shows an alternative arrangement to practise the present method.

FIG. 6 is a graphical illustration of the pressure course as a functionof time in accordance with the example.

DETAILED DESCRIPTION

The method is based upon the fluid pressure characteristics as afunction of time in a period of time immediately before shut-off to aselected moment in time after full or complete shut-off of the fluidflow.

FIG. 1 shows a simplified arrangement for determination of mass flux ina subsea oil well, in which a pressure sensor 17 is located immediatelyupstream of the well wing valve 13. The wellhead valve arrangementlocated at the sea bed 14 is illustrated schematically at 11. The valvearrangement 11 is supposed to be open.

In shut-off of oil and gas wells the total pressure increase can beexpressed as a sum of the following elements: pressure loss caused bypressure shock (hereinafter denoted as pressure surge), friction lossand hydrostatic pressure loss:

    Δp=Δp.sub.a +Δp.sub.j +Δp.sub.g    (1)

When shutting off oil and gas wells in a short period of time (a fewseconds), all of the essentials pressure loss elements will becomeavailable as static pressure below the shut-off valve. The pressureincrease occurs gradually with time and with different mutualcharacteristics, and the present method utilizes these characteristicsin the determination of the flow rate of the multi-phase flow.

When shutting off wing valve 13 a pressure shock or surge is observedbelow (upstream) the valve, measured by pressure sensor 17 in FIG. 1,and is present until the valve is fully closed. If the valve closesinstantaneously, a similar momentary pressure increase at the valve willbe observed. This effect is known as the water hammer effect (cf. G. Z.Watters "Analysis and Control of Unsteady Flow in Pipelines",Butterworths, 1984 og J. A. Fox "Transient Flow in Pipes, Open Channelsand Sewers", Ellis Horwood Ltd., 1989):

    Δp.sub.a ρ·a·Δu          (2)

where ρ--the fluid density, a--the acoustic velocity of the medium, andΔu--change in fluid flow velocity. When the valve is fully closed, Δucorresponds to the flow velocity of the medium immediately beforeclosure of the valve.

Practically simultaneously with the initial closing of the valve therewill be a gradual pressure increase below the shut-off valve 13 due tofriction loss, measured at pressure sensor 17. This pressure increase isin general linear with time, and also takes place after the valve hasbeen closed provided that the valve exhibits a linear closingcharacteristic. In real systems, however, one will have to performcorrelations with respect to the valve characteristic. The pressurecontribution from the friction loss can be expressed as follows:##EQU1## where f is the pipe friction factor, L is the pipe length inquestion, d is the pipe diameter, ρ is the density of the medium and uis the flow velocity of the medium.

Since u in equation 3 and Δu in equation 2 are equal, the density ρ inequation 3 can be substituted for the density of equation 2: ##EQU2##

This equation forms the basis for the determination of the multi-phaseflow mass flux immediately before valve shut-off. The friction factor fis known and the pipe diameter d is known, so is the acoustic velocityof the medium, which otherwise can be measured, as described in furtherdetail below, and the pressure surge pressure Δp, is found by measuringthe pressure change from the moment the valve starts closing to themoment when the valve is fully closed. The pressure contribution fromfriction including the pipe length L in question is determined asfollows.

When the valve 13 starts closing a pressure pulse will propagate in bothdirections from the valve, i.e., upstream and downstream. A pressurepulse propagating upstream in an oil well (down into the well) willoccur at the fluid sound velocity, i.e., its acoustic velocity. If theacoustic velocity is 200 m/s the pressure pulse propagates 200 meters ina second. The pressure pulse travelling down into the well at anacoustic velocity will stop the flow and make the friction lossavailable. This occurs gradually during travel of the pulse along thepipe, and at an arbitrary moment of time during travel the valveshut-off the pressure contribution from friction at a pipe length L fromthe shut-off valve will appear at the shut-off valve (measured bypressure sensor 17) after a time t and effect a pressure increase there:##EQU3## where a is the acoustic velocity of the composition. Byreplacing L in equation 4 by ta/2 for L in equation 5, the fluid flowvelocity becomes: ##EQU4## where Δp₁.sup.• is the friction losscontribution measured at moment of time t.sup.•. The composition flowvelocity is found by means of equation 6 above and measuringΔp_(f).sup.• in a time t' after the valve 13 is closed by means ofequation 6. Provided that the composition density is known, the massflux G of the composition can be found according to the followingequation:

    G=p·u                                             (7)

FIG. 2 illustrates the basic principle of the performance or behaviourof the pressure change occuring at shut-off of an oil well in which thepressure course p is shown as a function of time t, measured by, forexample, pressure sensor 17 in FIG. 1. As is evident from FIG. 2, thevalve starts closing at time t₁, and the pressure increasessubstantially linearly with a first slope or derivative to the moment oftime t₂, at which the valve has become fully closed. The pressuredifference between times t₂ and t₁ represents the pressure surgepressure Δp_(a) plus the friction loss contribution during the sameperiod of time. After time t₂ the pressure increase is represented bythe contribution from the friction loss Δp_(f) alone, which measured atmoment of time t.sup.• has a slope or derivative dp_(f) /dt which isdifferent from the derivative dp_(a) /dt within the period of time fromt₁ to t₂. At the moment of time t₃ substantially all friction loss(Δp_(f)) has been converted to static pressure. However, in oil wellsthere will be a gradual pressure increase over time caused byhydrostatic contribution from the formation.

As mentioned above, Δp_(a) is found by measuring the pressure increasewhich occurs during the period of time the valve is being closed, oranalyzing the pressure change derivative afterwards and substituting theinitial fluid pressure from the absolute pressure when the pressurechange derivative changes, i.e., when the contribution from the frictionloss starts taking over. As mentioned above the pressure will alsoincrease as a result of already released friction loss from time t₁, andΔp_(a) will have to be correlated in view of this contribution. Thiscontribution is usually substantially less than released friction lossafter time t₂. A moment of time t.sup.• is then selected after the valveis closed, and the contribution from the friction pressure loss dp_(f)/dt is determined. This value for change of pressure at time t.sup.• isinserted into equation 6 above together with f, t.sup.•, d and Δp_(a),after Δp_(a) has been corrected with respect to the friction losscontribution: Δp_(a) =Δp_(a) (measured)-Δp₁ (t₂ -t₁), where Δp_(a) isthe measured pressure increase from the friction loss calculated for theperiod of time t₁ to t₂. The contribution from the friction loss is incomparison low, and the measured Δp_(a) is often sufficient to determinethe mass flux of the composition.

Unknown Acoustic Velocity and Density

As mentioned above, density and acoustic velocity for unstable orunknown multi-phase compositions will have to be determined fromsimultaneous measurements. As illustrated in FIG. 3, this can be done byusing two extra pressure sensors 35 and 36, one of which is locatedimmediately downstream of the shut-off valve 33 while the second sensor36 is located at a known distance downstream of the reference sensor 35,e.g. at a distance of 20 meters. By measuring the propagation time t fora characteristic pressure pulse from the reference sensor 35 to thesensor 36 downstream over a distance L, the acoustic sound velocity a ofthe composition is found: ##EQU5## The measured a' is the sum of thefluid specific acoustic velocity a and the fluid flow velocity u. Intypical multi-phase flows from for example an oil well, the flowvelocity of the composition will lie in the range 1-10 m/s whereas thespecific acoustic velocity is about 200 m/s. Having a flow velocity of10 m/s, the flow velocity u can be found by inserting a' instead of a inequation 6 with a maximum error factor of 5%. The friction factor f isalso a function of the compositions flow velocity u, but since thefriction factor f changes insignificantly with changes in the flowvelocity u of the composition, and since u is far less than a, thefriction can be assumed to be constant, and the calculated flow velocityus in accordance with equation 6 will then be very close to the realvalue. The accuracy of the calculated u can be improved by, e.g.,performing repeated iteration with equation 6 and 8, or correlateaccording to acoustic models in view of the physical properties of thecomposition.

When the specific acoustic velocity a and the flow velocity u of thecomposition have been determined in accordance with equation 6, thecomposition density can be determined from equation 2 above, and hencethe composition mass flux.

The distance L between the reference sensor and the metering sensor isin general selected with respect to the specific acousticcharacteristics of the composition and the accuracy of the meteringequipment, i.e., how many registrations the equipment can perform perunit of time. The lower the sample frequency the longer the distance Lwill have to be. On the other hand, the higher the sample frequency, theshorter distance L will need to be. A typical distance L for measuringoil wells will be within the range of 20 to 50 meters.

Pure Gaseous Compositions

To measure gas flow in wells and pipelines, the only requirement is tomeasure the pressure surge pressure Δp_(a). As gas densities andacoustic velocities in general are easy to determine in view ofpressure, temperature and chemical composition, and provided, naturally,that also these parameters are known, the mass flux can be determined inaccordance with equation 2 and 7 above.

Alternative Embodiments

In pipelines permitting installation of several pressure sensors andwhere the composition characteristics are less predictable, it may beadvantageous to use two reference pressure sensors 47 and 45 (FIG. 4)located upstream and downstream respectively of the shut-off valve 43and providing two metering sensors 48 and 46 located at known distancesupstream and downstream, respectively, of the respective referencesensors 47 and 45. The mode of operation for this embodiment is similarto the one described above, except that the acoustic velocity a of thecomposition can be found directly by measuring the difference in thepressure pulse propagation speed from the shut-off valve 43 measured at45 and 47 to the respective metering sensors 46 and 48. ##EQU6## whereu_(N) is the pressure pulse propagation velocity downstream and u_(o) isthe pressure pulse propagation speed upstream. The flow velocity u ofthe composition is found from the equation u=0.5·(u_(N) -u_(o)) or bysubstracting the specific acoustic velocity a of the composition fromthe measured pulse propagation velocity: u=u_(N) -a, and the density ofthe composition can be calculated directly from equation 2 above. Theshut-off valve 43 will in this case replace the pressure pulse generatordescribed in NO Patent 174643.

In a further alternative embodiment, as illustrated in FIG. 5, twopressure sensors 57 and 58 can be used. Both sensors are locatedupstream of the well wing valve 51 at the wellhead. The sensor 57 servesas a reference sensor and is located immediately upstream of the valve51, whereas the sensor 58 is located at a known distance (a) from thereference sensor 57. This arrangement will in general operate in amanner similar to the embodiment illustrated in FIG. 3, but with thedifference that the reference sensor 57 serves both as reference fordetermination of the specific acoustic velocity of the composition andthe pressure course at the shut-off valve.

It should be noted that the description above is in respect of an idealhomogenous flow regime, and with the shut-off valve exhibiting a linearcharacteristic. However, control valves will not start throttling theflow until the end of the closing cycle is reached, and the contributionfrom the pressure loss will, in the closing phase of the valve, vary forinstance with the valve characteristics. The method must in practicalcircumstances be corrected for such factores.

EXAMPLE

Practical metering experiments were performed on a well in the North Seato verify the validity of the method. The experiments were performed inconnection with a pressure build-up test. After withdrawal of thestring, a quartz crystal gauge from Hewlett Packard was mounted in thegrease nipple at the well head at a location between the well head valveand the wing valve, in accordance with the schematical illustration inFIG. 1.

Reference data was provided with the simulating program PROSPER, whichwas fed with real pressure and temperature data from the separationstep.

A consecutive registration of the well pressure was performed with thepressure sensor for a period of about 3 minutes from zero productionflow, during wing valve shut-off, and to a moment of time where stablewell pressure was obtained. The pressure course during the experiment isillustrated in FIG. 6. As is evident from FIG. 6, the pressure increasedby about 3.0 bars during 3.6 seconds--the time required to close thevalve--this pressure representing the pressure surge Δp_(a). Thiscomplete closure of the valve appears from the break in the pressurecurve at time B in FIG. 6, whereupon the pressure increase was caused bycontribution from friction loss Δp_(f) alone. The pressure losscontribution Δp_(f) to the measured pressure surge Δp_(a) is omitted forsimplicity. FIG. 6 further shows that the pressure increasedsubstantially linearly from time B to time C, at which substantially allfriction loss had been made available as static pressure at the wingvalve, i.e., within about 25 seconds. The remaining pressure increaseafter time C is caused by hydrostatic pressure from the formation. ThePROSPER simulation with, among other parameters, a well head pressure of102.8 bars shows a mean density in the area below the wellhead of about500 kg/m³, and from equation 2 above, the flow velocity of thecomposition was found to be 3.0 m/s.

The PROSPER simulation showed a flow velocity of 3.7 m/s, which can besaid to be in good conformity with the flow velocity measured by thepresent method.

I claim:
 1. Method for measuring the flow rate in a fluid flow (30),particularly a two-phase flow comprising oil, water and gas from adevelopment well offshore, characterized in: performing a temporarytransistory shut-off of the fluid flow by means of a valve (33), andrecording the fluid pressure at a location (37) immediately upstream ofthe valve (33) from a moment of time when the valve starts closing to aselected moment of time after the valve is fully closed, and opening thevalve to re-establish the fluid flow, and determining the fluid massflux G according to the ratio ##EQU7## where ρ=fluid density, f=frictionfactor, d=pipe diameter, t'=a selected moment of time after closure ofthe valve, Δp_(f).sup.• is friction loss recorded at time t.sup.• andΔp_(a) is pressure surge pressure represented by recorded pressureincrease at the moment the valve is fully closed.
 2. The method of claim1, characterized in determining the velocity of acoustic pulsepropagation in the fluid by measuring pressure as a function of timeduring shut-off of the valve by a reference metering means (35) and ametering means (36) located at a known distance downstream of thereference metering means (35), and determining said acoustic pulsepropagation velocity according to the equation

    a=L/t.


3. The method of claim 1, characterized in determining the flow rate andacoustic pulse propagation velocity in a flowing multi-phase medium froma development well by a reference metering means (57) locatedimmediately upstream of the shut-off valve (51) and a metering means(58) located at a known distance upstream of the reference meteringmeans (57).
 4. Method for measuring the flow rate of a fluid flow (40)comprising at least two phases, by means of pressure sensors (45, 46)downstream and pressure sensors (47, 48) upstream of a pulse generatingmeans (43), characterized in using a quick-closing valve as said pulsegenerating means (43), and changing the valve (43) position fromsubstantially open to fully closed,recording the fluid pressure by thepressure sensors (47, 48) and (45, 46) from a time when the valve startsclosing to a selected moments time after the valve is fully closed, andthen opening the valve to re-establish the fluid flow, determining thefluid flow velocity and specific acoustic velocity according to theratio ##EQU8## where u_(N) is the pressure pulse propagation velocitydownstream and u_(o) is the pressure pulse propagation velocityupstream, and providing the fluid flow velocity u from the formulau=0.5·(u_(N) -u_(o)) or by substracting the fluid specific acousticvelocity a from the measured pulse propagation velocity: u=u_(N) -a, anddetermining the fluid density ρ according to the ratio

    Δp.sub.a =ρ·a·Δu         (2)

where Δu is the change of fluid velocity, a is the velocity of acousticpulse propagation in the fluid, thus determining the fluid flow rate Gaccording to the equation

    G-ρ·u                                         (7)

where u is the fluid flow rate immediately before the valve startsclosing.